Note Davoust

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Gas Price Formation,

Structure & Dynamics

Romain Davoust

April 2008

Note de l’IfriNote de l’Ifri

Gouvernance européenneet géopolitique de l’énergie



The Institut Français des Relations Internationales (Ifri) is a researchcenter and a forum for debate on major international political andeconomic issues. Headed by Thierry de Montbrial since its foundingin 1979, Ifri is a non-governmental and a non-profit organization.As an independent think tank, Ifri sets its own research agenda,

publishing its findings regularly for a global audience.With offices in Paris and Brussels, Ifri stands out as one of the rareFrench think tanks to have positioned itself at the very heart ofEuropean debate.Using an interdisciplinary approach, Ifri brings together political andeconomic decision-makers, researchers and internationallyrenowned experts to animate its debate and research activities.

The opinions expressed in this text are the responsibility of the

authors alone .

ISBN: 978-2-86592-278-9 © All rights reserved, Ifri, 2008

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1

CONTENTS

INTRODUCTION ..................................................................................... 2

Methodological note: ..........................................................................3

A] NORTH AMERICA ............................................................................ 5

1) A brief history of prices and regulation ...........................................5

2) Gas price trends .................................................................................63) Integration of spot and futures prices..............................................7

4) LNG prices...........................................................................................8

5) End-use prices....................................................................................9

B] EUROPE ....................................................................................... 11

1) The pricing structure in Continental Europe.................................11

2) Spot developments ..........................................................................13

3) LNG pricing .......................................................................................14

4) Retail prices ......................................................................................15

5) The case of the United Kingdom.....................................................16

5) a) main features............................................................................16

5) b) price history and formation.......................................................16

6) Table of European gas prices……………………………………..…...18

C] ASIA............................................................................................. 21

1) Gas sector overview.........................................................................21

2) LNG price determination and evolution in Asia............................21

3) End-use prices..................................................................................23

4) Table of Northeast Asian gas prices ..............................................26

CONCLUSIONS.................................................................................... 27

BIBLIOGRAPHY ................................................................................... 31



R. Davoust / Gas Price Formation, Structure & Dynamics

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Introduction

Our study, focused on gas prices in importing economies, describeswholesale prices and retail prices, their evolution for the last one ortwo decades, the economic mechanisms of price formation.

While an international market for oil has developed thanks tomoderate storage and transportation charges, these costs are muchhigher in the case of natural gas, which involves that this energy isstill traded inside continental markets. There are three regional gas

markets around the world: North America (the United States,importing mainly from Canada and Mexico), Europe (importing mainlyfrom Russia, Algeria and Norway) and Asia (Japan, Korea, Taiwan,China & India, importing mainly from Indonesia, Malaysia &Australia). A market for gas has also developed in South America, butit will not be covered by our paper.

In Europe and the US, due to large domestic resources andstrong grids, natural gas is purchased mostly through pipelines. InNortheast Asia, there is a lack of such infrastructures, so importedgas takes mainly the form of Liquefied Natural Gas (LNG), shipped onmaritime tankers. Currently, the LNG market is divided into two

zones: the Atlantic Basin (Europe and US) and the Pacific Basin (Asiaand the Western Coast of America). For the past few years, theMiddle East and Africa have tended to be crucial suppliers for bothLNG zones.

Gas price formation varies deeply between regional markets,depending on several structural factors (regulation, contractingpractises, existence of a spot market, liquidity, share of imports…).Empirically, the degree of market opening (which corresponds to theseniority in the liberalization process) seems to be the primarydeterminant of pricing patterns.

North America has the most liberalized and well-performing

natural gas industry in the world. Gas pricing is highly competitive andis based on supply/demand balances. Spot and futures markets aredeveloped. The British gas sector is also deregulated and thusfollows a similar paradigm. Gas-to-gas competition now prevails.Long-term contracting is still the dominant model in ContinentalEurope and Northeast Asia, because of their dependence on externalimports. Thus, pricing there is more rigid, and due to an indexationclause, gas prices closely follow the tendency of oil markets (as wewill see further, American and British prices are also coupled to oil,but for less contractual reasons).




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Logically, the first part of our study analyses North Americangas prices, the second part European prices and the third part Asianprices. Since American and British gas markets exhibit the samenature and similar pricing features, it would be more relevant to treatthem together. However, if these two markets are close conceptually,there is no specific price connection between them. Indeed, due tothe presence of the Interconnector, a pipeline passing under theChannel, UK prices tend to be rather linked to the EuropeanContinent’s. Therefore, in our paper, the case of the UK is simplystudied inside Europe, although in a dedicated paragraph.

While observing mid and long-period price series, we willobviously seek common trends, since price integration (convergenceor simple correlation) is generally evidence in favor of marketintegration. Price indications will thus guide us with a view to answertwo crucial questions:

1) Did liberalization policies succeed in the US and EU,in their attempt to make natural gas a freely tradedcommodity?

2) Is a world market for gas emerging? In other words,is natural gas becoming a worldwide tradedcommodity?

The first question concerns intra-regional integration ofmarkets: common price trends between local spot markets (in thecase of the US), between member states (in the case of EU), andbetween piped gas and LNG (in both cases).

The second question concerns inter-regional integration ofmarkets. In this view, the case of LNG will be of an overridingimportance. Indeed, the higher technical flexibility of the LNG supplychain implies rising LNG international arbitrage, cargoes beingdiverted to the most profitable destinations. Co-movements are thenexpected between regional quotes, leading to the potentialemergence of a world gas market with a single price.

Methodological noteIn order to facilitate comparisons, all prices (wholesale and retail)

have been converted into a common unit: dollars per millions ofBritish Thermal Units ($ / MBtu). Also, in order to flatten the usualvolatility or seasonality in gas prices, we always use yearly averageprices.

All prices displayed in figures, tables and text are nominalvalues (except figures n°11 and 13: prices are expressed in dollars of2000). Using market prices (which integrate inflation) is suitable forthe present study. Indeed, the presence of inflation doesn’t impedethe analysis of price determination or structure. Regarding pricetrends over time, inflation, with its distorting effect, can become more




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problematic. Real prices, deflated through constant values, usuallyoffer a clearer vision of gas sector fundamentals (for example,constant prices are required in order to assess the evolution of thebalance between reserves, production and consumption). However,more than the sense of trajectories, this paper tries particularly tocheck the parallelism between them (between spot and import pricesfor example) and from this point of view, inflation (an overwhelming,macroeconomic effect) doesn’t interfere.




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North America

1) A brief history of prices and regulation

The Natural Gas Act of 1938 orders companies to charge “cost-of-service” rates for interstate gas trade. Such quotes consist of historiccosts plus a reasonable return on investment (ETC, 2007). In 1954, aSupreme Court Judgement extended control to wellhead prices, butonly regarding gas sold by interstate pipelines. As a result, pricedistortions occur between interstate and intrastate markets on the onehand, and between gas and energies such as oil and coal on theother hand.

A partial deregulation of wellhead prices occurred in 1978 withthe Natural Gas Policy Act. But in the meantime, international energyprices soared due to the oil shocks, so when full de-regulation finallybecame effective seven years later, gas rates rose suddenly, creatingan extended market surplus called “the gas bubble”, which lasted untilthe mid-1990’s (ETC, 2007).

At the beginning of the 1980’s, gas transactions were long-term contracts between producers, pipeline traders and LocalDistribution Companies (LDC), including a minimum bill provision inorder to secure the value chain. In 1984, the Federal EnergyRegulatory Commission (FERC) Order n°380 released utility buyerssuch as LDC from the commitment to purchase the transportationcapacity they reserve, which led to a deep fall in average wellheadprices. Consequently, from 1986 until 2000, demand resumed itsgrowth with major reliance on imports from Canada (ETC, 2007).Figure n°1 thus shows that American wholesale prices rose steadilyover the period: the yearly average spot price at the Henry Hub

swelled from 1.70 $ / MBtu in 1989 to 2.75 $ in 1996.During the winter 2000-01, gas prices peaked to more than

4 $ / MBtu because of a structural supply shortage (Canadian exportswere not sufficient to fuel the increase of the US gas demand) (ETC,2007). Between 2001 and 2005, an upward thrust occurred in gasprices, in line with the “third oil shock”: Henry Hub quoted average8.80 $ / MBtu in 2005. Since spring 2006, the gas market hasslackened a bit, and so have prices.




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Figure n°1: Wholesale average prices of natural gas in US (1989-2006)

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89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06

year

$/MBtu

Wellhead Spot (Henry Hub) WTI spot

Source: US DOE, BP Statistical Review & Energy Prices & Taxes

2) Gas price trends

The North American market for gas consists of the United States,

Canada and, to a lesser extent, Mexico. The US natural gas market iscompetitive, liquid and transparent, to such an extent that gas-to-gascompetition now prevails. But this physical spot market is frequentlyvolatile. Therefore, since 1989, agents manage price fluctuation riskswith futures contracts on the New York Mercantile Exchange(NYMEX).

Henry Hub, a major pipeline junction in Louisiana is thereference point of the North American pricing system; rates for otherhubs are defined by difference from it. These quote gaps (called“basis differentials”) reflect the transportation costs required to bringthe gas to Henry Hub, but also correspond to market conditions at

different national hubs (ETC, 2007).Although American gas prices are set by supply/demand

equilibriums, independently from any reference to oil, they run parallelto petroleum trends in the long run. Indeed, due to inter-energysubstitution effects at the end-use side, monthly gas prices rangeinside a corridor formed by a lower limit, heavy fuel rate, and anupper limit, light fuel rate. Indeed, in case of a gas price spike,households switch to light fuel oil, large industries switch to heavy fueloil and power plants switch to coal (Maisonnier, 2005).




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More precisely, the Energy Treaty Charter states that sincethe restructuring of the North American gas industry, gas-to-gascompetition is the dominant pattern when the sector is in surplus, butwhen the market tightens, the correlation reappears due to inter-fuelreplacements. For instance, when the American gas market was stillat ease during the first part of the 1990’s (period of “gas bubble”), gasrates evolved in quite a different manner than a barrel of West TexasIntermediate (WTI) (figure n°1). Since the end of the 90’s and newrestrictions on gas supply in the US (fading domestic production),they seem to be moving more in line.

3) Integration of spot and futures prices

Several empirical studies (de Vanys & Walls 1993 & 1994, King &

Cuc 1996, Cuddington & Wang 2006, Park, Mjelde & Bessler 2007)suggest that liberalization policies (pipeline open access since FERCorder n°436 in 1985), by reinforcing spatial arbitrage activity in thelong run, have strengthened the US gas market integration. Acommon finding is that the number of co-integrated local markets hasincreased within the 5 to 10 years following the reform. Thisconvergence is simply proved by the rising price spread correlationsbetween geographical locations. Finally, Serletis & Rangel-Ruiz(2004, cited by Park, Mjelde & Bessler 2007) conclude that NorthAmerican natural gas prices are largely defined by Henry Hub pricetrends. Nevertheless, King & Cuc (1996) and Cuddington & Wang(2006, cited by Park, Mjelde & Bessler 2007) discover an East-West

spit inside the North American natural gas market, since the Westernside seems to be weakly integrated within the rest of the country.

To summarize, the North American gas sector is a single, fullyliberalized, highly competitive and strongly integrated market. Thisspot market maturity should then bolster the futures market efficiencyin its capacity to integrate the sum of private information andexpectations concerning gas supply and demand. In other words,prices as formed in the futures market should represent an accurateforecast of future spot prices. Indeed, Walls (1995, cited by Wong-Parodi, Dale & Lekov 2006) finds that gas futures prices are unbiasedpredictors of future spot prices. Wong-Parodi, Dale & Lekov (2006)

state that the futures market is a more accurate predictor of naturalgas prices within a two-year horizon than is the Short-Term EnergyOutlook (STEO) of Energy Information Administration. As anexplanation, Henry Hub forward prices are determined economicallyby the agent’s expectations while the STEO derives analytically froman extrapolation of past price trends.

However, Felder (1995) affirms that the deregulation of gasindustries has created new price volatility, and therefore one shouldgive up deterministic approaches of price forecasting and opt forrandom walk models.




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4) LNG prices

North America is part of the Atlantic Basin LNG market (with Europe).But in America, LNG trade is encompassed in the overall competitive

evolution that affects the whole gas and electricity sector. As a result,LNG price determination is more or less disconnected from oilreference, and follows the trends of the existing gas-to-gascompetition in the US.

Figure n°2 confirms this statement: pipeline import prices andLNG import prices follow a similar trajectory, which is given by marketconditions at Henry Hub spot. As for an explanation, LNG is importedthrough short-term contracts on a netback basis, including a constantreference to gas market yardsticks like Henry Hub (ETC, 2007). Moregenerally, such common movements between LNG, piped and spotgas (econometrically proved by Siliverstives, l’Hegaret, Neumann &

von Hirschausen, 2004) have witnessed the better integration ofAmerican gas prices since the industrial deregulation.

Figure n°2: Average import prices of natural gas in US (1989-2006)

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10

89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06year

$ / M B t u

Spot (Henry Hub) Pipeline import LNG import

Source: BP, Energy P&T

Besides, self-contracting practises with destination flexibilityhave been introduced along the LNG chain, which reinforcedcompetition in LNG pricing (ETC, 2007). Thus, figure n°2 displays thatLNG import rates, which were much higher than pipeline import ratesduring the 90’s, tends afterwards to equalize to this latter. Thisrelatively lower price of LNG can moreover be explained bytechnological improvements all along the LNG supply chain




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(liquefaction, shipping) and by progressive diversification of supplyingcountries. Finally, thanks to the new gas market environment in theUS, characterized by declining internal reserves and rising quotes,LNG import prices are becoming more and more interesting with aview to matching American gas needs in the future.

5) End-use prices

Figure n°3: End-use average prices of natural gas in US (1989-2006)

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$/MBtu

Spot (Henry Hub) Residential Industrial Power generation

Source: US DOE

Rates applied to the industrial and power sector tend to harmonizeover time by moving closer to the spot price. Walls (1994, cited byPark, Mjelde & Bessler 2007) has indeed discovered that the city gateprices at certain locations are co-integrated with field market prices(wellhead). Household tariffs are higher than other quotes by a factor2. This residential over-tariff (which is a world-wide feature) is causedby additional costs that are specific to that sector: distribution costs,which structurally represent a major part of the final price. Thosedistribution charges usually correspond to the commercial marginslevied by LDCs at the city gate before delivering to small consumers.

However, end-use sectors (residential, industrial andelectrical) have natural gas delivered under different technicalconditions; they have different demand functions, including a varietyof factors. But in spite of that variability, convergences betweenexisting ranges of price, combined with a relatively low level of gastariffs, attest the success of deregulation policies in the United States.




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6) US gas prices

Table of US gas prices ($/Mbtu)

WHOLESALE END-USE

yearSpot

(Hen.H.)Wellhead

Pipeimport*

LNGimport*

Households

Industry Power G

1989 1.70 1.64 1.76 2.15 5.47 2.87 2.36

1990 1.64 1.66 1.85 2.40 5.63 2.84 2.31

1991 1.49 1.59 1.76 2.29 5.65 2.61 2.11

1992 1.77 1.69 1.78 2.46 5.71 2.75 2.29

1993 2.12 1.98 1.96 2.13 5.98 2.98 2.53

1994 1.92 1.79 1.80 2.21 6.22 2.96 2.211995 1.69 1.50 1.44 2.23 5.88 2.63 1.96

1996 2.75 2.10 1.90 2.72 6.15 3.32 2.61

1997 2.52 2.25 2.09 2.66 6.73 3.48 2.70

1998 2.08 1.90 1.89 2.55 6.62 3.05 2.33

1999 2.27 2.12 2.16 2.40 6.49 3.01 2.54

2000 4.23 3.57 3.86 3.40 7.53 4.35 4.25

2001 4.06 3.88 4.31 4.22 9.34 5.08 4.47

2002 3.34 2.86 3.04 3.31 7.65 3.90 3.572003 5.62 4.73 5.07 4.65 9.34 5.71 5.40

2004 5.85 5.30 5.63 5.65 10.43 6.33 5.93

2005 8.80 7.11 7.85 8.01 12.45 8.30 8.23

2006 6.76 6.23 6.63 6.97 13.34 7.65 6.88

* average price

Source: DOE, BP, Energy P&T




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Europe

1) The pricing structure in Continental Europe

Continental Europe relies increasingly on gas imports. Transactionsgenerally regard large volumes extracted from giant fields. Naturalgas is imported through long-term contracts from Russia, Algeria,Norway, Nigeria or Libya (but gas can be bought inside the EuropeanUnion: the United Kingdom, Germany, the Netherlands, Italy…).

In Continental Europe, the pricing is based on the“replacement value” of gas, which corresponds to the value ofalternative energies on the final gas markets inside the buyer’scountry. This market value of gas is then netted back to the exportingstate’s border by subtracting intermediary charges to deliver to thecustomer (transportation cost, distribution cost and other costs), andthis gives the final reselling price (the producer price). Historically, thisconcept of long-term contract with a price based on replacementvalue was designed first for exports from the Dutch field of Groningen

(first large reserve discovery in Europe).

Moreover, contracts include a review clause: price is adaptedregularly in line with the development of the competitive situation ofgas in each of the residential, industrial and power sectors. In otherwords, the price formula is re-calculated (usually every three months)in order to reflect movements in the share of gas in power generation,and changes in the mix of the competing fuels, mainly light fuel oiland heavy fuel oil but also crude oil, coal, electricity or inflation (ETC,2007). More recently, since the creation of the Interconnectorbetween the UK and the Continent, a reference to gas-to-gascompetition has been integrated in the indices. But despite variations

in the shares of different components, the price of gas in ContinentalEurope remains mainly pegged to fuel oil products. The EnergySector Inquiry (ESI, 2007) empirically confirms that the rates ofEuropean long-term contracts are mainly linked to oil and oilderivatives, according to a volume-weighted indexation.




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Figure n°4: Average import price of natural gas in EU (1986-2006)

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4.06.08.0

10.

12.14.

86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06

year

$/MBtu

Brent Gas imports


Indeed, in figure n°4, due to a wide indexation to fuel oilproducts, the import contracts average price in Continental Europeclosely tracks the oil barrel, although with a lag of more or less 6months. According to Siliverstives, l’Hegaret, Neumann & vonHirschausen (2004), import gas prices in Europe follow developmentsin North Sea Brent Crude Oil (a reference for many gas importcontracts in Europe) with a lag of about 4-8 months. As shown infigure n°5, purchase prices all over Europe consequently move in anidentical manner.

Figure n°5 Average import prices in EU member states (1999-2006)

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99 00 01 02 03 04 05 06

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$/MBtu

Austria Belgium Finland

Germany Greece Ireland

Netherlands Spain Brent spot

Source: Energy P&T




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To be more precise, the indexation pattern varies by importsource. According to the ESI, imports from Russia, Norway and theNetherlands have a similar indexation with a pegging of over 80% tofuel oil products and as a result, gas purchased from those countriesdisplay similar price levels. By contrast, Algerian gas is mostly linkedto crude oil for 70% (it is the cheapest gas sold in Europe).

Price indexation also varies according to the purchaser’sregion, with a big split between the UK and Continental Europe. In theUK, fuel oil products account for only 30% of the total pegging. OnContinental Europe, the importance of fuel oil is much higher: 80% inWestern Europe, 95% in Eastern Europe.

The observation of price convergence between differentmember states provides a good indicator of the achievement of theEuropean internal gas market since liberalizing reforms wereundertaken (European Single Act of 1986, EU Gas Directives of 1998

& 2003). For instance, using co-integration analysis of import prices,Asche, Osmunden & Tveteras (2001, 2002, cited by Robinson, 2006)infer that the French, Belgium and German markets are integrated.

2) Spot developments

It seems obvious that the continental import model is not favorable toa reactive gas price based on gas-to-gas competition. There is in facta weak price-elasticity of demand on the Continent, which comesfrom two factors: gas imports often involve wholesale players

(national companies) on both sides of the exchange, and natural gasis used less in power plants in Continental Europe than in the UK orthe US (ETC, 2007). Despite substantial measures aimed at creatinga single competitive gas market (removal of destination clauses andtake-or-pay obligations, mandatory Third Party Access), long-termcontracts still remain the dominant practice for imports of natural gas,although with a fostered flexibility.

Owing to the new regulatory environment, several gas hubshave nevertheless developed through Western Europe: Zeebrugge inBelgium, Bunde in Germany, Title Transfer Facility (TTF) in theNetherlands (virtual)… The pricing at those spots reflects the supply

and demand situation. But, because they still welcome mainly largeindustrial players, such trading hubs have reduced activity. Therefore,they have a low liquidity, which allows for price manipulations (ESI,2007). Neumann, Siliverstovs & von Hirschausen (2005, cited byRobinson 2006) find for example that prices at Zeebrugge and Bundeare not connected. Moreover, hub prices are much more volatile thanlong-term contract rates. They display a seasonality trend, due toclimate conditions (a fall in demand during summer, a rise during thewinter) (ESI, 2007)




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3) LNG pricing

In Continental Europe, LNG imports rely on traditional long-termcontracts mainly from Algeria, and also from Nigeria or Trinidad. Price

is pegged to crude oil or oil products, but due to increasingcompetition from pipeline gas, the indexation pattern for LNG tends tofollows the same structure as on-shore gas, with references to coal,electricity… More generally, the liberalization process on theContinent is making LNG pricing more competitive (ETC, 2007).

Figure n°6 clearly supports these facts. The pegging to crudeoil is obvious. Consequently, pipe import and LNG import displaysimilar price levels year after year. Siliverstives, l’Hegaret, Neumann& von Hirschausen (2004) assert that this co-movement of LNG andpiped gas, caused by similar contract and price structure, providesevidence of regional gas price integration in Continental Europe.

Moreover, price competitiveness of LNG relative to piped gas isconstantly improving: while in 1999, LNG deliveries were moreexpensive than piped gas, LNG became cheaper in 2002; and by2006, the LNG price was 6.62 $ / MBtu, piped gas costs7.32 $ / MBtu.

Figure n°6: Gas imports average price in EU (1999-2006)

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$/MBtu

EU pipe gasimport

EU LNGimport

Brent

Source: Energy P&T




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4) Retail prices

Figure n°7: Residential gas prices in EU member states (1998-2006)

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98 99 00 01 02 03 04 05 06

year

$ / M B t u

Austria

Czech Republic

Denmark

Finland

France

Greece

Hungary

Ireland

Italy

Netherlands

Poland

Slovak Repub-

Spain

Source: Energy P&T

Figure n°8: Industrial gas prices in EU member states (1998-2006)

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98 99 00 01 02 03 04 05 06

year

$ / M B t u

Czech Republik

Finland

France

Greece

Hungary

Ireland

Italy

Netherlands

Poland

Portugal

Slovak Republik

Spain

Source: Energy P&T

Two main features emerge: since 1998, end-use prices have stronglyrisen on average, and the price spread between member states haseven widened. On those two points, gas directives seem to havemore or less failed in the short term since the opening policy wastheoretically supposed to generate both lower prices and priceconvergence. However, conjuncture factors, like the recent surge in




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international oil markets, account for the boost in retail gas prices(final gas prices in the residential, industrial and power sector areindeed based on the market value of substitutes, mainly fuel oil).

Moreover, the persistent price divergence across Europe has

a structural explanation, such as substantial differences in nationaltaxation (especially in the residential sector, where the percentage oftaxes ranges between 5% in the UK and 33% in Netherlands as of2006). Recently, an important bias was introduced by the terminationof cross-subsidies between end-use sectors (large users wouldindirectly finance small users). Put more simply, the gaps can belinked to differences in transportation and distribution costs that areincluded in the final price (for example, Eastern countries, closer fromRussia, bear lower transportation charges). Asche, Osmunden &Tveteras (2002) justify the relative price discrepancy through Europeby pointing to the natural complexity of gas import contracts, whichdepend on a wide range of elements, including political risk and even

oil taxation.

However, Robinson (2007) analyses retail gas pricestrajectories in the long term inside the European Union. Based on asample of member states, he notices a long-run convergence ofnational prices between 1978 and 2004, reflected by diminishing pricedifferentials over time.

5) The case of the United Kingdom

a) main featuresContrary to the Continent, which is still dependent on long-termcontracts, the British gas industry is fully liberalized. In this sense, itfollows closely the current North American paradigm, thus displayingsimilar features: spot transactions, responsive short-term pricing andgas-to-gas competition. But while Henry Hub represents a physicalspot, the National Balancing Point is a virtual point, an intangibletrading place which quotes prices for all gas passing through thenational grid according to a system of “entry-exit” rights (ETC, 2007).Linked to the NBP, a futures market for gas has developed at the

International Petroleum Exchange.

b) price history and formationThe Natural Gas Act of 1986 triggered a large movement ofderegulation, by introducing Third Party Access and also byterminating British Gas’s monopoly selling and monopsony buying ofgas. In the meantime, the electric power industry was liberalized in1989. This relieved power plants from the obligation to use coal, thussetting a more price-elastic demand for gas. In 1998, the supply of




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the residential sector was opened to free competition, which drovedown NBP rates (ETC, 2007).

Since then, trends of gas rates are more or less coupled withthe trajectory of alternate fuels (gas oil, heavy fuel oil). Thus, despite

the existence of a well-developed spot market for gas in the UK,which theoretically involves an autonomous gas price formationbased on national fundamentals, figure n°9 establishes a correlationbetween NBP prices and crude oil references over the recent period.

Figure n°9: Comparison between NBP spot, EU import and oil barrel(1999-2006)

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Brent spot NBP average spot EU average pipe import


Due to a recent decline in North Sea production, the UnitedKingdom switched in 2004 from being a net exporter to a netimporter, and this led to a strengthening in British gas prices. Indeed,as shown in figure n°9, the NBP rate suddenly soared from anaverage of 4.46 $ / MBtu in 2004 to 7.38 $ in 2005. This price spikecan also be explained by a more temporary factor, namely the coldwinter of 2005/06.

Since 1998, the British gas sector is connected with theContinent through the Interconnector, a pipeline linking the Bacton

Terminal with the Zeebrugge Hub in Belgium. The long-term exportcontracts to the Continent include a clause that allows the supplierarbitrage with spot prices in the UK. The price implications of theInterconnector, which enables two-way gas flows, are displayed infigure n°9. NBP spot rates and Continental contract prices showcommon up and down trends over the period. Indeed, gas trade andarbitrage through the Interconnector had the effect of setting a pricechannel between British and Continental gas (the UK market hadpreviously remained isolated).




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More precisely, before 2004, NBP prices were lower thanContinental prices. These latter held as a ceiling to the UK market,which was then still wide. Nevertheless, in October 2003, withtensions emerging on British supply, Continental rates become alower limit to NBP quotes. However, due to the Interconnector, a priceequilibrium was set between the UK and the Continent (Maisonnier,2005)

As recognized by the International Energy Agency (2002, citedby Ferreira, Soares & Araujo, 2003), liberalization policies in the UKhave brought substantial benefits to consumers. Retail prices arelower than the EU average, especially in the household sector.

6) Table of European gas prices

Wholesale prices (average import prices, except NBP = spot price)($/Mbtu)

Year NBP EUpipe

AUT BEL FIN DEU IRL NLD ESP EULNG

1999 1.58 1.88 - 2.06 2.02 1.86 2.14 1.99 1.63 2.00

2000 2.71 2.79 - 2.83 2.35 2.83 2.3 2.43 3.24 3.09

2001 3.17 3.51 3.55 3.52 2.58 3.64 2.67 3.13 3.93 3.54

2002 2.37 3.16 3.34 3.03 2.55 3.27 2.77 2.84 3.36 3.14

2003 3.33 3.91 4.06 - 3.21 4.03 3.08 3.57 4.28 3.63

2004 4.46 4.2 4.48 4.27 - 4.4 3.81 3.9 4.37 3.89

2005 7.38 5.33 5.87 - - - 4.42 4.95 5.45 5.1

2006 7.87 7.32 7.66 - - - - - 7.33 6.62





19 © Ifri

End-use prices (H = Households, I = Industry, P = Power Generation)($/Mbtu)

Finland France Germany

Year H I P H I P H I P

1998 4.69 3.85 3.33 12.14 4.38 - 11.25 4.94 4.09

1999 4.34 3.56 2.99 10.77 4.09 - 10.61 4.49 3.87

2000 4.43 3.63 3.15 9.65 4.95 - 10.37 5.22 4.26

2001 6.14 3.50 3.03 11.19 5.48 - - - -

2002 5.60 3.53 3.03 11.82 5.07 - - - -

2003 6.94 4.41 3.78 14.49 6.72 - - - -

2004 7.49 4.73 4.04 15.12 7.28 - - - -

2005 8.28 5.28 4.60 16.40 9.17 - - - -

2006 9.79 6.89 6.20 19.64 11.45 - - - -


Italy Netherlands

Year H I P H I P

1998 19.19 4.76 - 10.93 3.69 3.38

1999 17.73 - - 10.25 3.24 -

2000 - - - 9.98 4.63 -

2001 - - - 11.15 4.88 -

2002 - - - 12.70 4.57 -

2003 - - - 16.74 6.18 -

2004 21.62 8.35 - 18.96 - -

2005 22.87 9.77 - 22.23 - -

2006 26.02 12.62 - 24.99 - -





20 © Ifri

Spain United Kingdom

Year H I P H I P

1998 14.81 3.83 3.56 9.18 3.02 3.51

1999 13.35 3.65 3.33 8.92 2.86 3.19

2000 13.65 4.87 4.58 8.13 2.91 2.89

2001 14.11 4.89 - 7.96 3.90 3.09

2002 13.80 4.60 - 8.81 4.07 2.95

2003 16.51 5.67 - 9.77 4.58 3.60

2004 17.87 5.99 - 11.75 5.63 4.50

2005 19.02 7.06 - 13.38 8.30 5.96

2006 21.03 9.86 - 17.88 10.66 7.64





21 © Ifri

Asia

1) Gas sector overview

The current Asian market for gas is composed of Japan, Korea,Taiwan, and for a few years, China and India. These countries importfrom Malaysia, Indonesia, Australia, the Middle East and the UnitedStates. The construction of an international pipeline grid being toocostly due to the specific geographical aspect of the Asian Continent,importing economies are almost totally dependent on LiquefiedNatural Gas, supplied through medium and long-term contracts. InJapan, there is a substantial coupling between gas and electricitysectors, LNG purchases being mainly routed to electricity generators.Because of this linkage, gas markets in Northeast Asia are verticallyintegrated, although in Japan and Korea, a few juridical steps havebeen made recently towards the opening of the retail supply (Skeer,2004).

2) LNG price determination and evolution in Asia

Liquefied Natural Gas import prices in the Pacific Basin are moreexpensive by roughly 1 $ / MBtu compared with the Atlantic Basin.This premium (the “Asian premium”) is due to long-haul shipping ofgas, high charges applied to the use of LNG terminals and lastly theabsence of competition from piped gas.

Since the 90’s, the Northeast Asian pricing formula is based

on the Japanese pattern, and is P=a+bX type. It is split between twocomponents: a base part (a), constant, set firmly by negotiation, anda floating part, termed “escalator” (X), designed to reflect variations inoil rates. Usually, a coefficient (“pass-through factor”, b, inferior tounit) is used to integrate petroleum tendencies in the LiquefiedNatural Gas price.

A very common price escalator in the Asia Pacific region is theJapanese Crude Cocktail (JCC), a basket of different crude oilsimported from the Middle East. Such a benchmark is another factor ofthe Asian gas price premium: shipping crude oils from the Middle




22 © Ifri

East to Japan is particularly expensive while, for example, Europeangas prices are only linked to pre-burner competitive prices – mainly oilproducts (Fujime, 2005).

Moreover, floor and capping mechanisms were introduced in

the pricing system in order to regulate the impact of barrel ups-and-downs. This curving factor, which acts as a “shock absorber”, thusmitigates the direct effect of higher or lower oil prices for the sake ofthe buyer or seller (Suzuki). Nevertheless, with the emergence of tightcompetition for LNG in Asia, those price limits have been softened oreliminated (ETC, 2007).

For three decades, LNG pricing in Asia has been punctuallyre-adjusted in line with the ups-and-downs in the oil market, in orderto maintain a financial compromise between importers and suppliers.More precisely, the base price (a) and the pass-through factor (b)were re-calculated (a being lowered and b raised, or conversely).

Over the recent period, with the barrel skyrocketing, the base price forLNG has been set at a higher level in line with the new fundamentalsof the oil market, but the linkage coefficient to oil has been flattened inorder to reduce the potential effects of the barrel surge. Moreover, theprice-capping mechanism, by maintaining LNG quotes under acertain threshold, has more or less led to a de facto decoupling frompetroleum conditions (ETC, 2007).

Figure n°10: LNG average import price in Japan (1986-2006)

0

2

4

6

8

1012

14

8 6

8 7

8 8

8 9

9 0

9 1

9 2

9 3

9 4

9 5

9 6

9 7

9 8

9 9

0 0

0 1

0 2

0 3

0 4

0 5

0 6

year

$/MBtu

Japan LNG

Crude oil import costin Japan

Source: Energy P&T

The linkage to crude oil appears in figure n°10, and isexplained by the JCC reference in the LNG pricing formula. However,since 2002 and the oil price flare-up, purchase rates of LNG haverisen, but to a much lesser extent. This is due to moderatinginstruments in the LNG price: price-capping, pass-through factor.

Geographically, China and India represent a convergencepoint in Asian LNG pricing. Indeed, these countries started to importLNG at a time when Asian demand for natural gas was still low(beginning of 2000’s). Moreover, the important size of these two




23 © Ifri

potential markets triggered an active competition between LNGsuppliers to penetrate them. In this context, Chinese and Indianprices for LNG were negotiated at particularly low levels with aweaker pegging to oil rates. Such prices still more or less prevaildespite the strengthening of hydrocarbon markets. Consequently,when renewing their contracts, Northeast Asian LNG purchaserstarget lower rates in accordance with Chinese prices. Importers alsoinvoke reduced LNG technical costs to obtain price cuts.

However, gas price determination in Asia should becomemore and more competitive due to the diversification of LNG importsources, densification of gas infrastructures (new terminals andpipelines projects), multiplication of players at different levels of thesupply chain (from the exporting country to the end-user), andincreased pressure from competing fuels in electricity generation(clean coal and nuclear).

3) End-use prices

Contrary to the case of United States or Europe where wholesale andretail trends are coupled, there is an important dichotomy betweenimport and end-use rates in Japan. In figures n°11 & 12, one noticesthe particularly high level of quotes applied to households, which areby far the most expensive of the three global regions. For example,during 2006, households would pay 13.34 $ / Mbtu on average in theUS, while they would be charged more than 34 $ in Japan.




24 © Ifri

Figure n°11: Sectoral end-use gas prices and crude oil prices in Japan(1985-2000)

Source: International Energy Agency, provided by Skeer, 2004

Figure n°12: End-use gas prices in Japan

0.05.0

10.15.

20.25.

30.35.

40.

98 99 00 01 02 03 04 05 06

year

$ / M B t u

Industry

Residential

LNG

Source: Energy P&T

In fact, retail price structure in Japan can be explained by theindustrial organization, in other words by a differentiated access pointto gas. Residential or commercial customers, who can be suppliedonly through the final distribution grid, pay both transmission anddistribution charges. Industrial users, who can connect directly tohigh-pressure pipelines, pay only transmission charges (which arerather high charges). Electric utilities usually receive gas deliveries at




25 © Ifri

their own LNG terminals, and therefore bear lower costs. As aconsequence, retail prices for electricity are closely linked to the trendof crude oil (figure n°11), while industrial and residential rates,including substantial transmission and distribution charges, are moreloosely linked to the barrel. Finally, in Japan, gas prices for electricityare twice lower than gas for industry, which is itself twice or threetimes cheaper than residential tariffs (Skeer, 2004).

However, as shown in figure n°13, there is an importantvariability in end-use prices throughout Asia. In the case ofhouseholds, distribution charges can vary substantially from onecountry to another, leading to ranges in residential rates (Skeer,2004).

Figure n°13: Industrial gas prices in Japan, Korea, Chinese Taipeiand Thailand

Source: International Energy Agency, provided by Skeer, 2004




26 © Ifri

4) Northeast Asian gas prices

Table of Northeast Asian Gas Prices ($ / Mbtu)

Japan Korea

YearLNG*

Households

Industry PowerG

LNG*Households

Industry PowerG

1998 29.68 9.89 - - - - -

1999 3.18 33.24 10.72 - 3.15 - - -

2000 4.73 35.95 12.58 - 2.04 - - -

2001 4.64 32.45 11.29 - 4.95 - - -

2002 4.32 30.18 9.92 - 4.41 - - -

2003 4.82 33.20 10.69 - 5.03 - - -

2004 5.23 35.32 10.90 - 5.74 12.62 9.50 8.14

2005 6.04 34.60 11.15 - 6.96 14.67 10.90 10.20

2006 7.18 34.40 12.09 - 8.75 17.82 13.76 13.25

*average import priceSource: Energy P&T




27 © Ifri

Conclusions

First of all, we noted the fundamental importance of regulation in gaspricing. Price efficiency, levels, transparency and the related socialwelfare varies substantially between the USA, the UK, ContinentalEurope and Northeast Asia since those regions are simply situated atdifferent stages of the liberalization movement. In other words, theyare at different points in the temporal evolution towards a freed gasmarket, along an East-West axis:

Northeast Asia is in the first stages of theliberalization process, although measures or trendshave been recently taken in this direction. A morederegulated sector could emerge during the 2010’s.

Continental Europe, where the gas market hasbeen legally opened since the 2000’s, is still in thelong-term transition between an old, rigid, regulated,monopolistic model and the targeted competitivesituation.

Then, the United Kingdom, whose gas markethas been open since the 90’s, is obviously moreadvanced in the deregulation procedure, but structuralimprovements still need to be done, such as increasingthe liquidity at the National Balancing Point.

Finally, North America, liberalized since the80’s, is by far the most competitive area: gas marketopening is now complete, and the market for gas isnearly a “total market”. The American gas sectorrepresents a paradigmatic target for European andAsian markets.

In the United States, the liberalization movement provedpragmatically a success: US gas tariffs are converging, and arecurrently lower than in the rest of the world. Gas pricing is essentiallyintra-sectoral, but alternate energies like oil and coal still play a priceregulator, according to the economic rule of substitutable goods onthe consumer’s side. Despite the existence of a regulatory frameworkfavorable to gas-to-gas competition and moderate prices, the recentemergence of physical constraints (declining domestic resources,rising import needs) should raise US gas prices in the future.




28 © Ifri

In Europe, the case seems more complicated. It is maybe tooearly to assess the final effect of the directives on gas prices. Therecent upwards bias induced by the third oil shock furthermorecomplicates the legibility of gas price trajectories. At its core, there isa technical, economic, juridical and fiscal disparity of gas sectorsthroughout the Continent. Despite decisive steps made towards asingle gas market, this complexity of the European gas world mightdelay retail price harmonization in the short-term.

There is a common agreement that indexation of Europeanprices on oil products should still prevail in the near future, becausetraditional long-term contracting represents for players an essentialway to secure gas transactions (reservation of transportationcapacities…). But owing to higher flexibility requirements and thegrowing use of gas in electricity production, the oil reference shouldbe less determining. More relevant indicators, like gas spot prices atvarious hubs or power quotes could play an increased role. Moreover,

contract prices should coexist with spot prices in the landscape of thecoming decades, considering the forecasted importance of spot hubsin European gas.

Concerning price levels in Europe, high rates could bepersistent due to a strengthened structural dependence on externalimports. However, competitive pressures generated by deregulation,entry of multiple players at different stages of the value chain andgeographical diversification of import sources should maintain gasprices in bearable limits.

Regarding Asia, gas price levels are rather expensive due to along geographical distance between producing regions andconsuming locations, which indeed involves high transportation costs.The Asian pricing system is particularly rigid, so a lot of additionalwelfare can be expected from liberalization policies. In any case,multilateral competitive pressures following the rising importance ofAsia in international gas should naturally generate improved marketefficiency. Substantial price cuts can also be obtained throughtechnological progress in the production and transportation of LNG.Nevertheless, despite an active diversification of supplying sources,the boosting Asian LNG demand, fueled by China or India, mightgenerate a spike in LNG prices inside this region

We turn now to the second question asked in the introduction

of this paper: is a global price for natural gas emerging? This issue isdirectly related to the case of LNG, since LNG shipped throughmaritime tankers allows for intercontinental gas trade (LNG becomesvery competitive compared with piped gas over long distances).Continuously declining LNG costs should furthermore reinforceinternational LNG trade and arbitrage.

Currently, there is important LNG arbitrage between theUnited States and Europe. With Africa and the Middle East becomingsignificant suppliers of LNG, an arbitrage activity is also developingbetween the Atlantic Basin and the Asia Pacific Basin. Siliverstives,




29 © Ifri

l’Hegaret, Neumann & von Hirschausen (2004) thus mentions co-movements between LNG import prices in Europe and in Japan by2004. Nevertheless, North American price moves slightly differentlythan in other regions. Figure n°14 confirms the integration of LNGquotes between Europe and Japan, and the existing split with NorthAmerican prices. However, by 2006, one observes a priceconvergence and equalization between the three LNG regions: LNGaverage import cost is 6.62 $ / MBtu in Europe, 7.05 $ in the US and7.18 $ in Japan.

Figure n°14 LNG average import price(1999 2006)

0.001.002.003.004.005.00

6.007.008.009.00

99 00 01 02 03 04 05 06

year

$/

Mbtu

US

Europe

Japan

Source: Energy P&T

In Europe and the US, LNG represents a small portion of thenatural gas supply. This tends to restrict LNG arbitrage in its ability totransmit price signals and initiate a gas price harmonization betweenregional markets. Moreover, international spot arbitrage might belimited by the persistence of long-term contracting as a mean tosecure LNG capital investments.

Finally, there is a widespread feeling that, rather than a singleworld gas price, we might observe correlations or convergencesbetween regional prices within the next several years. Of course, thisdoesn’t preclude the thesis of a unique gas price in the long-term.

The dollar, invoicing currency in international trade, has beenthe unit mainly used in gas imports to the United States, Europe andAsia. In the recent context of the dollar depreciation, the UnitedStates suffers relatively more from the recent surge in purchaseprices than Europe and Asia, where the rise can be partly eliminatedthrough currency translation (such a situation prevails more generallyin the hydrocarbons market). Thus, the United States could partlyloose their natural price advantage over other gas regions formonetary reasons (unfavorable exchange rate), combined withsectoral ones (higher dependence on external imports) and also dueto globalization (more price channels between regions).




30 © Ifri

Concerning the European Union, gas import contracts shouldbe increasingly expressed in euros, as the dollar becomes lessrelevant. In the meantime, exporting countries (especially inside theMiddle East) tend to diversify their selling currencies beyond thedollar. Indeed, they opt for stronger currencies, intending to cushiontheir revenue shortfall caused by the dollar depreciation.




31 © Ifri

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